1. Field of the Invention
The present invention relates to meter electronics and methods for processing sensor signals for a multi-phase flow material in a flowmeter.
2. Statement of the Problem
It is known to use Coriolis mass flowmeters to measure mass flow, density, and volume flow and other information of materials flowing through a pipeline as disclosed in U.S. Pat. No. 4,491,025 issued to J. E. Smith, et al. of Jan. 1, 1985 and Re. 31,450 to J. E. Smith of Feb. 11, 1982. These flowmeters have one or more flow tubes of different configurations. Each conduit configuration may be viewed as having a set of natural vibration modes including, for example, simple bending, torsional, radial and coupled modes. In a typical Coriolis mass flow measurement application, a conduit configuration is excited in one or more vibration modes as a material flows through the conduit, and motion of the conduit is measured at points spaced along the conduit.
The vibrational modes of the material filled systems are defined in part by the combined mass of the flow tubes and the material within the flow tubes. Material flows into the flowmeter from a connected pipeline on the inlet side of the flowmeter. The material is then directed through the flow tube or flow tubes and exits the flowmeter to a pipeline connected on the outlet side.
A driver applies a force to the flow tube. The force causes the flow tube to oscillate. When there is no material flowing through the flowmeter, all points along a flow tube oscillate with an identical phase. As a material begins to flow through the flow tube, Coriolis accelerations cause each point along the flow tube to have a different phase with respect to other points along the flow tube. The phase on the inlet side of the flow tube lags the driver, while the phase on the outlet side leads the driver. Sensors are placed at different points on the flow tube to produce sinusoidal signals representative of the motion of the flow tube at the different points. The phase difference between the two sensor signals is proportional to the mass flow rate of the material flowing through the flow tube or flow tubes. In one prior art approach either a Discrete Fourier Transform (DFT) or a Fast Fourier Transform (FFT) is used to determine the phase difference between the sensor signals. The phase difference, and a vibrational frequency response of the flow tube assembly, are used to obtain the mass flow rate.
In one prior art approach, an independent reference signal is used to determine a pickoff signal frequency, such as by using the frequency sent to the vibrational driver system. In another approach, a phase locked loop (PLL) is used to lock the frequency of the pick-off or reference signal to the drive frequency. In another prior art approach, the vibrational response frequency generated by a pickoff sensor can be determined by centering to that frequency in a notch filter, wherein the prior art flowmeter attempts to keep the notch of the notch filter at the pickoff sensor frequency. These prior art techniques work fairly well under quiescent conditions, where the flow material in the flowmeter is uniform and where the resulting pickoff signal frequency is relatively stable. However, the phase measurement of the prior art suffers when the flow material is not uniform, such as in two-phase flows where the flow material comprises a liquid and a solid or where there are air bubbles in the liquid flow material. In such situations, the prior art determined frequency can fluctuate rapidly. During conditions of fast and large frequency transitions, it is possible for the pickoff signals to move outside the filter bandwidth, yielding incorrect phase and frequency measurements. This also is a problem in empty-full-empty batching, where the flowmeter is repeatedly operated in alternating empty and full conditions. Also, if the frequency of the sensor moves rapidly, a demodulation process will not be able to keep up with the actual or measured frequency, causing demodulation at an incorrect frequency. It should be understood that if the determined frequency is incorrect or inaccurate, then subsequently derived values of density, volume flow rate, etc., will also be incorrect and inaccurate. Moreover, the error can be compounded in subsequent flow characteristic determinations.
In the prior art, the pickoff signals can be digitized and digitally manipulated in order to implement the notch filter. The notch filter accepts only a narrow band of frequencies. Therefore, when the target frequency is changing, the notch filter may not be able to track the target signal for a period of time. Typically, the digital notch filter implementation takes 1-2 seconds to track to the fluctuating target signal. Due to the time required by the prior art to determine the frequency, the result is not only that the frequency and phase determinations contain errors, but also that the error measurement encompasses a time span that exceeds the time span during which the error and/or two-phase flow actually occur. This is due to the relative slowness of response of a notch filter implementation.
The result is that the prior art flowmeter cannot accurately, quickly, or satisfactorily track or determine a pickoff sensor frequency during two-phase flow of the flow material in the flowmeter. Consequently, the phase determination is likewise slow and error prone, as the prior art derives the phase difference using the determined pickoff frequency. Therefore, any error in the frequency determination is compounded in the phase determination. The result is increased error in the frequency determination and in the phase determination, leading to increased error in determining the mass flow rate. In addition, because the determined frequency value is used to determine a density value (density is approximately equal to one over frequency squared), an error in the frequency determination is repeated or compounded in the density determination. This is also true for a determination of volume flow rate, where the volume flow rate is equal to mass flow rate divided by density.
In a typical oil well, the well output commonly includes not only oil but also can include varying amounts of water and natural gas in the well output stream. The oil well output therefore typically comprises a multi-phase fluid stream. As a result, the well stream is usually fed into a separator device. The separator device extracts one or more components from the well stream. The separator device can comprise a two-phase separator or can comprise a three-phase separator. A two-phase separator typically extracts entrained gas from a multi-phase fluid. The output of the two-phase separator can comprise a gas output and a two-phase fluid without entrained gas. For example, where the well stream comprises oil, water, and natural gas, then the two-phase separator liquid output can comprise a two-phase oil and water flow stream. A three-phase separator can separate out the entrained gas and can also separate the water from the oil.
However, separators do not completely separate the flow components. For example, the extracted gas can include a small amount of residual liquid. This is commonly termed carryover or liquid carryover, as the gas outlet of a separator is typically positioned physically higher than a liquid outlet. In addition, the oil output of a three-phase separator (or the oil and water output of a two-phase separator) may still include a small amount of entrained gas. This is termed carryunder or gas carryunder, as the liquid/water outlet of a separator is typically positioned physically lower than a gas outlet.
Measurement of the separator output according to the prior art comprises measuring each separator output stream with a flowmeter of some type. The measurement assumes that there is a negligible liquid carryover in the gas output of the separator and assumes that there is a negligible gas carryunder in the oil/water output. This assumption is made because in the prior art the entrained gas and/or liquid cannot be substantially instantaneously determined and therefore cannot be accurately determined. However, the carryover and carryunder are typically present, resulting in a significant inaccuracy in prior art well production measurements. The inaccuracy is compounded by combining the gas and liquid prior art measurements.